The present invention relates to constructing a MONOWELL and more particularly to apparatus and methods for constructing a monodiameter wellbore for a monodiameter casing and a monobore production delivery system and still more particularly to drilling and completing a well using apparatus and methods to achieve a monodiameter wellbore, installing monodiameter casing and liners and installing a fullbore production delivery system.
Traditional well construction, such as the drilling of an oil or gas well, includes a wellbore or borehole being drilled through a series of formations. Each formation, through which the well passes, must be sealed so as to avoid an undesirable passage of formation fluids, gases or materials out of the formation and into the borehole or from the borehole into the formation. In addition, it is commonly desired to isolate both producing and non-producing formations from each other so as to avoid contaminating one formation with the fluids from another formation.
As the well is drilled deeper, conventional well architecture includes casing the borehole to isolate or seal each formation. The formation may also be cased for borehole stability due to the geo-mechanics of the formation such as compaction forces, seismic forces and tectonic forces. The casings prevent the collapse of the borehole wall and prevent the undesired outflow of drilling fluids into the formation or the inflow of fluids from the formation into the borehole. The borehole may need to be cased due to equivalent circulating density and hydraulics reaching or exceeding the formation pore pressure or exceeding the fracture gradient pressure thus allowing fluids or gases to transfer between formations and borehole. If the formations are non-producing, or not of the desired producing interval, (some intervals are producing but at low levels) the formations can be cased together. If shallow water flows (where water flows several hundred feet below the seabed floor), or if there is potential communication among formations, then the formation is cased. The casings extend downhole and are sequentially placed across the formations through which the wellbore or borehole passes. The casings may be liners which do not extend to the surface of the wellbore. Traditionally steel casing has been used to case off formations.
In standard practice, each succeeding casing placed in the wellbore has an outside diameter significantly reduced in size when compared to the casing previously installed, particularly to accommodate hangers for the inner strings, and may be described as a series of nested casing strings. The borehole is drilled in intervals whereby a casing, which is to be installed in a lower borehole interval, is lowered through a previously installed casing of an upper borehole interval. As a consequence of this procedure, the casing of the lower interval has a smaller diameter than the casing of the upper interval. Thus, the casings are in a nested arrangement with casing diameters decreasing in the downward direction.
The use of a series of casings, which have sequentially reduced diameters is derived from long experience. The number of casings required to reach a given target depth is determined principally by the properties of the formations penetrated and by the pressures of the fluids contained in the formations. If the driller encounters an extended series of high pressure/low pressure intervals, the number of liners required under such circumstances may be such that the well cannot usefully be completed because of the continued reduction of the casing diameters required. Along with the downsize serial casing operations, the production tubulars may have to be downsized as well further reducing the delivery capacity of the well.
If the borehole extends through a formation that tends to cave in and thus causes the borehole to be very unstable, casing inserts must be installed to keep the borehole open. A casing insert is a type of emergency casing string which shores up an unstable formation and is an additional section of casing that is set through this unstable portion of the borehole. By requiring a casing insert for this unstable formation, an even smaller size casing than was planned is then required to complete the well. This reduces the diameter of the well and thus the ultimate internal diameter available for the production tubulars. The casing insert may not be possible, requiring that the well be sidetracked, resulting in a substantial reduced diameter wellbore.
The disadvantages of nesting casing and liners is apparent in slim-hole drilling. A slim-hole well is one in which 90% or more of the length of the well is drilled with bits smaller than 7 inches in diameter. See SPE 19525: An Innovative Approach to Exploration and Exploitation Drilling: The Slim-Hole High-Speed Drilling System by Walker and Millheim, September 1990. Slim hole drilling focuses on starting with a small borehole and finishing with an even smaller borehole for production.
The casing is fixed in the borehole by a cement layer between the outer wall of the casing and the wall of the borehole. During the drilling of the wellbore, annuli are provided between the outer surfaces of the casings and the borehole wall and a composition, sometimes referred to as “oil field” cement, is introduced in the annulus for cementing the casing within the wellbore. The casing is commonly cemented in place after the installation of each casing. When the casing is located in its desired position in the well, a cement slurry is pumped via the interior of the casing and around the lower end of the casing and upwards into the annulus, thereby causing the cement slurry to drive the drilling fluid upward in the annulus. As soon as the annulus around the casing is sufficiently filled with the cement slurry, injection of cement into the well is stopped and the cement slurry is allowed to harden. The cement sets up in the annulus, supporting and positioning the casing and forming a substantially impermeable barrier which divides the well bore into subterranean zones.
Ultimately the borehole reaches the target and is drilled through a hydrocarbon-containing formation or reservoir to produce hydrocarbons. The borehole may not be cased through the hydrocarbon-containing reservoir to allow substantially unrestricted influx of fluids from the formation into the borehole. When the formation is so weak that it will collapse, the uncased borehole section is completed with a liner. It is common practice to install a liner in the reservoir by suspending the liner in the borehole through the reservoir and then pumping a cement slurry into the annulus. After the cement has set to a hardened mass, perforations are extended through the liner and the cement body into the hydrocarbon-containing formation around the well in order to allow in-flow of reservoir hydrocarbon fluids, such as oil or gas, into the well.
The liner may be provided with slots to allow fluid influx into the borehole. The liner is usually secured at its upper end to the lower end of the non-productive barrier casing previously installed in the borehole. Because the slotted liner must pass through the previously set casing, it must have an outer diameter which is less than the inner diameter of the cased section. Over time, the formation may collapse and settle against the outer wall of the liner so that the area around the liner gets filled with particulates. U.S. Pat. Nos. 5,366,012 and 5,667,011 teach an expandable liner which is expanded by an expansion mandrel by moving the mandrel through the liner to radially expand the liner to a larger diameter in the borehole.
The purpose of the cement body around the casing is to fix the casing in the well and to seal the borehole around the casing in order to prevent vertical flow of fluid alongside the casing towards other formation layers or even to the earth's surface. Casing is traditionally cemented in place for two main reasons. (i) one to seal off and prevent leak paths between permeable zones and/or surface, and (ii) to give support and stability to the casings. The cement prevents fluid exchange between or among formation layers through which the wellbore passes, and prevents the undesirable migration of fluids between zones or gas from rising up the wellbore. It is important that there is no gas or fluid leakage after the cement has set and the well is completed.
A problem generally encountered during cementation of the casing is, that due to various factors, such as the existence of varying pressure and temperature gradients along the length of the casing and shrinkage of the cement body during hardening thereof, relative displacements occur between the casing and the hardened cement mass which may result in poor bonding or cracking between the cement body and the casing. Poor bonding may result in the presence of a so-called micro-annuli between the casing and cement body, micro-annuli may extend along a substantial part of the length of the casing. The occurrence of a micro-annuli is particularly dangerous in gas wells as substantial amounts of gas might escape to the surface. In some cases hydrogen sulfide or natural gas can escape into the atmosphere. This condition may also lead to surface or ground water contamination. The resulting problems are very expensive to correct.
The poor bonding of the cement may be attributed to drilling fluid contamination or to bonding of the cement to the casing after the cement has set and/or oil or mill finish contamination on the surface of the casing or it can be attributed to aggressive drilling or aggressive pressure subjection and large pressure differs prior to it hardening and during the operation. As is well known in the art, hardening of cement causes generally a slight reduction of the volume of the cement. A more fundamental cause is the loss of hydrostatic head during the curing of the cement such that the formation pressure exceeds the annulus pressure and gas migration occurs causing channeling of the cement and subsequent leakage. Various additives and application techniques relative to the cement have been used in order to reduce the occurrence of this problem. During cementing operations, it is common to both reciprocate and rotate the casing during the cement pumping operation to break up or close any cement channels around the casing. Also compressible cement slurries have additives that entrain gas, which during the cement pumping operation, are compressed and as the hydrostatic head is lost during curing of the cement, the entrained gas subsequently expands and prevents loss of the pore pressure such that formation gas is prevented from migrating into the annulus. This technique, however, results in a lower strength cement. Thixotropic cement slurries depend on the cement achieving high gel strengths in very short time periods. If there is a rapid static gel strength obtained, gas migration and channeling are reduced or prevented. These specialized cement additives are expensive and require specific operational techniques. Thus, it is essential that a good bonding be created between the cement body and both the casing and the borehole wall.
There are various types of wells such as land based wells and offshore wells. Well applies to anything that produces oil, gas, water, or hydrates. Offshore wells may be shallow or deep water wells. A shallow offshore well is typically drilled from a platform that is in water up to 3,000 feet in depth. A deep water well is drilled from a floating platform or vessel with a riser extending from the sea floor to the platform or submersible rig. Any water deeper than 5,000 feet requires a drilling vessel, typically a drill ship.
Various types of casing may be installed in the well including conductor casing, surface casing, intermediate or production casing and production liners. Typically a land based well starts with a 20/18–⅝″ or larger diameter casing and telescopes down through two or three intermediate casings, to a final casing size of typically 6⅜″ with a 5″ production liner installed. Each casing is secured in place with cement filling an annulus having a size typically varying from 1 to 10 inches over the length of the casing and may be as much as 14 to 21 inches or greater at a wash out in the borehole wall.
FIG. 1 is a schematic of a conventional deep water well completion. The size and number of casing and tubing strings will increase or decrease depending upon the well plan based upon, for example, the depth of the well, the production tubing delivery size, the structural support and the seabed formation support. If the seabed formation is unconsolidated and has little support, then the structural or conductor casing is larger and is set deeper. If the initial conductor casing is in rock, then it can be smaller with substantially less depth. For example, initially a structural or conductor casing and riser are lowered from a drilling platform and driven, drilled or jetted into the sea floor to provide support for a surface casing. The structural or conductor casing may or may not be cemented.
FIG. 1 illustrates a 36 inch by 16 inch by 10¾ inch by 7 inch casing program with the addition of one or more tubing strings. After the 36 inch conductor casing is set, one or more surface casings is installed. A borehole is drilled for a 20 inch surface casing which is lowered into place with a 21″ surface casing riser attached thereto. A subsea wellhead with blowout prevention equipment, such as an 18¾ inch blowout preventer, is installed on the surface casing. The subsea wellhead may be supported by a structural casing.
Further, a borehole may be drilled through the riser and wellhead and through a problematic formation to extend a structural casing through the problem formation. For example, there are salt formations in the deepwater of the Gulf of Mexico. The structural casing forms a barrier across the formation while also supporting the wellhead. The structural casing has a thicker wall and provides a stable support frame for and can carry the load on the subsea wellhead. A 16 inch structural casing may be drilled, installed and cemented through a salt formation to seal off the salt formation from the wellbore being drilled. It should be appreciated that if there is no problematic formation, such as a salt zone, a shallow water flow zone, loss circulation zone, or other problem zone, then a structural casing is not needed to seal off the problematic area but it will support the subsea or platform wellhead, depending on well type.
Another borehole is then drilled for a 13⅜ inch intermediate casing string which is lowered into the borehole, attached to another riser, and cemented in place. Next a borehole may be drilled for another intermediate casing, such as a 11⅞ inch casing, and cemented in place. The borehole for the production casing string, such as a 9⅝ inch casing, is drilled and the production string is landed. It may or may not be cemented in place. The drilling is performed through blowout prevention equipment.
Subsequently, a production tubing is installed and is supported within the wellhead on a tubing hanger, a hanger system or anchor system. The production tubing is typically 3½ inch tubing but may be as small as 1½ inches or as large as 12 inches. After the tubing hanger seals have been tested, the blowout prevention equipment is removed and a Christmas tree or subsea tree is installed. If the well is land based or being drilled from a platform, the blowout prevention equipment is at the surface. If the well is a subsea well, the blowout prevention equipment and tree are installed subsea. Also, the tubing can be installed through the subsea tree or subsea template. Thus, conventional techniques use a plurality of concentric casing strings with varying diameter and do not have a monodiameter architecture. It should be appreciated that conventional well architectures may vary depending upon the geological or drilling conditions.
As a consequence of the nested arrangement of the casings, a relatively large diameter borehole is required at the upper part of the borehole. Because the upper casing(s) has to be larger than the lower casing(s) for the lower casing(s) to pass through the upper casing(s), the upper portion of the borehole typically has a much larger diameter than the intended ultimate diameter at the bottom of the borehole. Large boreholes are disadvantageous in that they generate large amounts of cuttings and require increased volumes of drilling fluid and cement. In the standard well casing configuration, large volumes of cuttings are produced initially and heavy logistics are required during early phases of drilling. Generally speaking, larger borehole sizes take longer to drill than smaller diameter boreholes at equivalent depth. For example, increased drilling rig time is involved due to required cement pumping and cement hardening. Further, a large borehole diameter often takes larger fluid and horsepower capacity rigs generating increased costs due to heavy casing handling equipment and large drill bits. Thus conventional equipment results in larger boreholes drilled for each formation, larger sized equipment, greater fluid volumes, and larger casing strings than is absolutely required to provide a borehole for a well, for an injecting or producing or monitoring.
Utilizing a large borehole often causes the usage of a wide variety of equipment and fluids that might not achieve maximum efficiency for the drilled borehole. If problems arise, additional fluids must be pumped and additional cement must be used to cement the formation to overcome the variances encountered during conventional well construction, otherwise a side track must be performed.
Conventional well architecture, engineering, and planning accounts for potential problem migration, well plan variance, and contingency. Therefore, large tolerances in equipment and procedures are provided in anticipation of variances in the length and/or composition of the formations, geomechanics, and growth/loading design. Compensation in the well architecture, engineering, and planning must be included in the well plan for contingency due to such large tolerances, including drilling for additional casing strings for geomechanical problems and sidetracks and re-drills for the installation of casing inserts prior to reaching the reservoir formation.
It can be appreciated that the problems with conventional well architecture are exacerbated in a deepwater well. In addition to the larger boreholes to be drilled, the larger sized completion equipment, the greater fluid volumes, and the larger casing strings, a deepwater well also requires large risers extending to the water's surface. The risers require the use of additional large fluid volumes, such as for drilling fluids and cement, to drill and cement the casing strings. Further, the large risers add substantial expense and additional large sized completion equipment.
It has long been an objective to achieve a monodiameter well where the wellbore is drilled from spud to total depth using one borehole size. For example the monodiameter well might be spudded with a driven conductor 7⅝″ to 9⅝″ in diameter. Thereafter, a borehole is drilled for each borehole section, perhaps a 7″ diameter. The borehole is then cased or lined with expandable casing or liners. Cement or some other innovative sealing composition is then used for the annular pressure seal. The next section of borehole is drilled using the same sized overgauge hole drilling and then cased or lined again with the same size expandable casing or liner. The process is repeated to target depth. See SPE 65184: “Towards a Mono-Diameter Well—Advances in Expanding Tubing Technology” by Benzie, Burge, and Dobson presented at the SPE European Program Committee Conference held Oct. 24–25, 2000.
The monodiameter well is designed based on the borehole size required across the reservoir. Rig capacity and all the drilling and completion equipment for the entire well is sized to the reservoir borehole size. Upon the advent of the monodiameter well, the telescoping well design with all its associated and myriad selection of drilling and completions equipment will become obsolete. The monodiameter well will achieve dramatic reductions in well construction costs. The challenge to the industry is to develop the full suite of enabling and complimentary technologies that will be required to drill and complete a monodiameter well. This suite of equipment will include drilling equipment, reaming while drilling (RWD), bi-center bits, energy balanced bits, near bit reamers, open hole annular sealing, well control procedures, well control equipment, and wellheads among others.
Expandable tubulars are being developed whereby casings and liners are expanded diametrically after they are placed in wellbores. The ultimate use of expanded tubulars is in a monodiameter well, whereby the entire well is drilled and cased using effectively one hole size. A solid steel tubular can be readily expanded using forces, either mechanical or hydraulic, available on most drilling and workover rigs. Expandable tubulars can be used in open hole either as a temporary drilling liner or as a permanent liner tied back to the previous casing string. See SPE 54508: “The Reeled Monodiameter Well” by Pointing, Betts, Bijleveld, and Al-Rawahi, presented at the 1999 SPE/CoTA Coiled Tubing Roundtable, May 25–26, 1999, and SPE 65184: “Towards a Mono-Diameter Well—Advances in Expanding Tubing Technology” by Benzie, Burge, and Dobson, presented at the SPE European Petroleum Conference, Oct. 24–25, 2000.
The concept of expanding a solid tube is relatively simple. A mandrel or “pig” whose outside diameter is greater than the tube's inside diameter is forced through the tube, thereby plastically deforming the tubing material to a larger diameter size. A solid tubular can be expanded using a cone of ceramic, tungsten carbide or hardened steel that is either mechanically pulled through the tubular or hydraulically pushed. The solid tubular can be expanded to around 30%–40%, although a range from 10%–20% will probably be more typical. The combination of expansion cone radius, material characteristics, expansion ratio, annular seal material, and gauge tolerance of the open borehole or casing within which the tubular is to be expanded, all determine the expansion forces and the tolerances or fit of the final expanded tubular in the wellbore. During the expansion process, the tubular strength increases since the expansion process is a cold working of the material. However, the collapse strength of a post expanded tubular is less than that of the pre-expanded tubular but it is within the design limits expected for the required borehole pressures.
One of the requirements of expandable casing/liners is to run a drill bit through the casing and drill a hole of a greater diameter than the previous casing. The next section of casing will then be run through the previous one and expanded against it. Thus, an enlarged wellbore having a diameter greater than the external diameter of the preceding installed casing must be drilled such as by “overgauge hole drilling” which encompasses the use of expandable bits, bi-center or eccentric bits or equivalent, reaming while drilling (RWD), under-reamers or similar tools and other novel drilling methods known to those skilled in the art, such as expandable/retractable stabilizers. Typical bits for overgauge hole drilling include bi-center bits and eccentric bits. A bi-center bit has a well-defined pilot bit section and an eccentric wing mounted further back on the bit body. An eccentric bit resembles more of a conventional bit, but a flank on the high-lobe side has a longer profile than on the other side. Eccentric bits are generally used in softer formations whereas bi-center bits are more commonly used in harder formations. The major difference of both bi-center and eccentric bits over under-reamers is that a section of borehole can be drilled to the required size in one run. However, an under-reamer provides a smoother and more diametric borehole wall.
At a desired depth, or when it is otherwise decided to case or line and cement the wellbore, an expandable casing or liner, whose greatest external (outside) diameter approximates, i.e., is only slightly smaller than the internal diameter of the casing or liner previously installed, is lowered through the previously installed casings or liners and into the newly drilled open enlarged borehole. The lowered casing or liner is a tubular made of a deformable material. The deformable casing/liner may have a decreased wall thickness. The lowered casing/liner is positioned in relation to the wellbore so that the upper end of the lowered casing/liner overlaps the lower end of the previously installed casing.
In expanding the expandable casing/liner, a die member, such as a mandrel or cone, is drawn or pumped through the length of the lowered casing to expand the casing in-situ. The die member has a suitable shape and composition, such as hardened steel, and is adapted or sized and shaped to expand the liner to the diameter of the previously installed casing. The die member is shaped or designed to provide at least substantially uniform expanded or deformed liner segment of circular or approximately circular periphery.
The upper end of the die member is connected to a running string and is pulled through the casing. Further, the die member may have a fluid tight seal, such as a cupseal, for sealing the die member within the casing and allowing sufficient fluid pressure to produce movement of the die member. Any suitable wellbore fluid or liquid available can be used for displacing the die member. To ease the expansion process, the inside diameter of the casing may be lubricated to allow the die member or expansion cone to move smoothly through the casing. The rate of upward adjustment or movement of the die member by upward movement of the running string and the application of pressure below the die member may be correlated so as to reduce movement of the die member up through the casing with concurrent gradual deformation and expansion of the casing, providing an expansion achieving an external diameter equal to or approximating, preferably slightly greater or larger than, that of the previously installed casing.
Threaded connections of lengths of expandable casing or liner remain the primary connection of choice. However, the connection has to be internally flush to allow the die member to pass through the connection, and externally flush to allow expansion to occur with constant expansion force. SPE 54508: “The Reeled Monodiameter Well” by Pointing, Betts, Bijleveld, and Al-Rawahi, presented at the 1999 SPE/CoTA Coiled Tubing Roundtable, May 25–26, 1999, discloses using coiled casing that maintains a single diameter of well bore throughout. Coiled casing can be used in the production of a monodiameter wellbore as well as tubular jointed expandable casing. Coiled casing can be expanded or installed non-expanded. A reeled monodiameter casing or liner has the same throughbore.
The expansion causes a virtual forced fit at the overlap of the upper end of the expanded lower casing/liner into the lower end of the previously installed casing. Thus, hangers are not required since the casing/liner is supported by the previously installed string. A constant through-bore is maintained at the overlap. The well is then subsequently completed by internally cladding the last casing string. Cladding the overlapped portions of the adjacent casings allows the lower casing to be supported at the cladding by the upper casing and allows the upper and lower casings to be pressure sealed at the overlap. The pipe over the area (overlap) to be cladded may include a corrosion resistant coating. One type of expandable tubular is disclosed in U.S. Pat. No. 6,085,838, hereby incorporated herein by reference.
The new well concept of using expandable casing and liners necessitates a narrow annuli in the range of 3 to 4 inches on diameter or less between the casing/liners and the borehole wall. Thus a quality borehole and optimum borehole size are required. The wellbore or borehole must have diametric efficiency. Diametric efficiency is the maintenance of the optimum hole size regardless of other well construction requirements or constraints. Preferably diametric efficiency maintains the optimum borehole size from the surface through the producing reservoir. The use of expandable casing/liners requires the maintenance of diametric efficiency to achieve a monodiameter well. Diametric solutions that maintain or improve diametric efficiency in a range of applications from multilaterals, high pressure/high temperature (HPHT), extended reach, horizontals and deepwater environments and remedial applications (i.e. side tracks) must be developed to use expandables.
Referring now to FIG. 2, there is shown a bell-end design disclosed in the SPE 54508 article. The annulus is split up into two parts: (i) where the liner is expanded against the previous casing/liner, either full length or overlap, and (ii) where the casing is expanded over the open borehole section.
The annular clearances between the casing/liner and borehole wall must allow cement slurries to displace the drilling fluid effectively. The interface or overlap between casing/liner strings must have the mechanical ability of the interface to hold axial loads and must have the hydraulic ability to form a pressure tight seal between the two casing/liner strings.
A simple expansion of metal against metal does not provide a reliable seal. Elastomeric seals are used to provide a pressure seal between the overlapped casing ends. Inside a previous casing or a gunbarrel hole through hard formations, a polymer or an elastic rubber coating may be applied externally to the casing/liner. This can deform elastically with the expansion of the casing/liner and form a seal between the casing/liner and/or formation.
A thicker layer of heat softening rubber, which can be coated on the outside of the expandable pipe, may be used in slightly overgauge boreholes. The thermal plastic rubber is reformed in-situ to its final shape by performing the casing/liner expansion process at a more elevated temperature, achievable by heating the well either before or during the expansion process.
Previously, a variety of cement compositions have been used for cementing in open hole applications. However, cement is undesirable for use with expandable casing. Oilfield cement or hydraulic cement compositions are incompressible and tend to resist the expansion of the casing or liner making the expansion more difficult. Thus, expansion of the casing/liner can lead to the crushing of the cement, and consequent loss of effectiveness regarding the zones. This problem is exacerbated by the small annular clearance associated with expandable casing/liners. With the new well concepts as described and the narrow annuli created in the range of 3 to 4 inches on diameter or less, other isolation materials must now be considered. Isolation materials must be ductile in order to form an appropriate seal. Conventional cement will be particularly brittle and weak in such thin sheaths or thicknesses and is hence an inappropriate sealing medium. Therefore, a composition with comparable strength to cement, but with greater elasticity and compressibility is required for cementing expandable casing.
Other problems may be encountered using oilfield cement or hydraulic cement as the sealing composition for expandable casing/liners. If the cement composition gels or sets prior to accomplishing the expansion, the cement composition is crushed in the annular space between the walls of the well and the expandable casing or liner whereby it does not function to seal the expanded casing or liner in the wellbore.
A conventional cement sealant composition under expansion conditions, with appropriate cement recipe to prevent the pre-maturely setting of the cement, may be used. Sealant compositions are required for sealing expandable casings or liners in well bores. Such compositions are compressible and maintain the properties required to provide a seal between the walls of the wellbore and the expanded casings or liners. Several types of sealants materials have been tested. Two materials are silicon gel and a two-component silicon rubber. Suitable wetting agents may be used such as barite or iron micropellets. The silicon gel is a highly viscous material. The two-component silicon rubber consists of two materials mixed in equal volume and weight. The mixture will automatically set, but a retarder may be added to control setting times. Silicon gels or rubbers are very ductile.
Prior to the expansion, the sealant material may be pumped into the annulus between the walls of the well bore and the unexpanded casing or liner in a similar manner to conventional cementing techniques. Once in place, the casing is expanded and the material allowed to set. In a severely washed out borehole, such as soft formations with wash outs and ledges, the sealant material may not be adequate.
In the traditional well, the wellbore may be open 3 to 5 days before stability of the borehole wall becomes a problem. After that, portions of the borehole wall may start to fall into the borehole. In using expandable casing/liners, longer intervals are going to be drilled thus leaving the borehole open for longer than 3 to 5 days. Thus there is a much longer time period than in conventional drilling during which the borehole wall is unsupported by casing during drilling. It is important that the borehole wall remain stable for these longer periods of time. Therefore, special drilling fluids must be used to drill the enlarged boreholes for expandable casing/liners to ensure the stability of the borehole over longer time periods.
Drilling fluid is circulated downwardly through the drill string, through the drill bit and upwardly in the annulus between the walls of the well bore and the drill string. The drilling fluid functions to remove cuttings from the well bore and to form a filter cake on the borehole wall. As the drilling fluid is circulated, a filter cake of solids from the drilling fluid forms on the walls of the well bore. The filter cake build-up is a result of initial fluid loss into permeable formations and zones penetrated by the well bore. The presence of the filter cake reduces additional fluid loss as the well is drilled.
In addition to removing cuttings from the well bore and forming filter cake on the well bore, the drilling fluid cools and lubricates the drill bit and maintains a hydrostatic pressure against the well bore walls to prevent blow-outs, i.e., to prevent pressurized formation fluids from flowing into the well bore when formations containing the pressurized fluids are penetrated. The hydrostatic pressure created by the drilling fluid in the well bore may fracture low mechanical strength formations penetrated by the well bore which allows drilling fluid to be lost into the formations. When this occurs, the drilling of the well bore must be stopped and remedial steps taken to seal the fractures. Such remedial actions are time consuming and expensive.
It is preferred to drill as long an interval as possible without having to stop drilling and case the borehole. However, in order to insure that fracturing of low mechanical strength formations penetrated by the well bore and other similar problems do not occur, it may become necessary to case and cement the borehole. As previously discussed, it is preferred to avoid frequently installing and cementing casing because drilling must be stopped and frequent casing of the borehole may cause a reduction in the producing borehole diameter.
Another problem that occurs in the drilling and completion of well bores is that when the well bore is drilled into and through unconsolidated weak zones or formations. Unstable materials such as clays, shales, sand stone and the like make up a high percentage of the formations in which wells are drilled, and a majority of well bore problems are a result of the instability of such materials, particularly shale instability. Shales are sedimentary rocks that contain a variety of clays. Shales containing montmorillonite, often referred to as smectite clays, swell and disperse when contacted by water. Shales which swell upon contacting water are often referred to as heaving or sloughing shales. Such shales upon contact with aqueous drilling fluids swell and fracture rendering the well bore wall unstable. In such cases, the well bore wall sloughs into the well bore. Sloughing of shale and other similar unstable materials into the well bore can cause the drill string to become stuck and can enlarge the well bore resulting in large subterranean cavities. Additionally, when sloughing occurs while the drill bit is being changed at the surface, the well bore fills up and must be cleared before drilling can proceed.
Furthermore, the heaving unstable material suspended in the drilling fluid increases its solid content, and as a result, the viscosity of the drilling fluid increases to the point where the drilling fluid must be chemically treated to reduce its viscosity or it must be diluted followed by the addition of weighting material to maintain its mud weight. The instability of clays, shales, sand stone and the like is also caused by hydraulic pressure differential leading to fluid transport and by pressure changes near the well bore as the drilling fluid compresses pore fluid and diffuses a pressure front into the formation.
Consolidating unconsolidated weak zones or formations formed of clays, shales, sand stone and the like while drilling a well bore prevents sloughing of the clays, shales, sand stone and the like into the well bore and prevents the need for implementing time consuming and costly remedial steps. It is preferred to increase the mechanical strength of the well bore whereby hydrostatic pressure exerted on the well bore by the drilling fluid does not cause fractures or the like to occur in the well bore. Such fractures cause drilling fluid to be lost and also require stoppage of the drilling operation and costly remedial steps to be taken.
Another significant advantage of increasing the mechanical strength of the well bore is the reduction or elimination of casing intervals at which casing or liners are cemented in the well bore which reduces or eliminates the overall time and cost of cementing the well. An additional advantage is that the well bore has a larger diameter in the production zone, due to fewer casing intervals, which increases productivity.
A monobore is a term used in the industry for a fullbore production delivery system. OTC 8585: “Case History, Well Completion and Servicing Strategies for the Hibernia Field” by Wylie, Maier, Shamloo, Huffman, and Downton presented at the 1998 Offshore Technology Conference, May 4–7, 1998, defines a monobore. To address overall completion criteria, a monobore design was chosen for the Hibernia Field for the initial completions. This design allowed flowbore access across the well's pay zone without diameter restrictions (not necessarily constant diameter).
In conventional completions, there are internal valves and gauges which project into the bore of the completion tubular. These narrow the inside diameter of the completion tubulars. Each restriction in the completion tubulars causes a pressure drop across that point causing scale and corrosion to occur at these points. The narrowing of the completion tubulars also reduces flow and therefore production.
The present invention overcomes the deficiencies of the prior art